A well capable of producing oil or gas will typically have a well structure to provide support for the borehole and isolation capabilities for different formations. Typically, the well structure includes an outer structure such as a conductor housing at the surface that is secured to conductor pipe that extends a short depth into the well. A wellhead housing is landed in the conductor housing with an outer or first string of casing extending from the wellhead and through the conductor to a deeper depth into the well. Depending on the particular conditions of the geological strata above the target zone (typically, either an oil or gas producing zone or a fluid injection zone), one or more additional casing strings will extend through the outer string of casing to increasing depths until the well is cased to its final depth. Each string of casing is supported at the upper end by a casing hanger that lands in and is supported by the wellhead housing, each set above the previous one. Between each casing hanger and the wellhead housing, a casing hanger seal assembly is set to isolate each annular space between strings of casing. The last, and innermost, string of casing extends into the well to the final depth and is referred to as the production casing. The strings of casing between the outer casing and the production casing are typically referred to as intermediate casing strings.
When drilling and running strings of casing in the well, it is critical that the operator maintain pressure control of the well. This is accomplished by establishing a column of fluid with predetermined fluid density inside the well that is circulated down into the well through the inside of the drill string and back up the annulus around the drill string to the surface. This column of density-controlled fluid balances the downhole pressure in the well. A blowout preventer system (BOP) is also used to as a safety system to ensure that the operator maintains pressure control of the well. The BOP is located above the wellhead housing and is capable of shutting in the pressure of the well, such as in an emergency pressure control situation.
After drilling and installation of the casing strings, the well is completed for production by installing a string of production tubing that extends to the producing zone within the production casing. The production tubing is supported by a tubing hanger assembly that lands and locks above the production casing hanger. Perforations are made in the production casing to allow fluids to flow from the formation into the productions casing at the producing zone. At some point above the producing zone, a packer seals the space between the production casing and the production tubing to ensure that the well fluids flow through the production tubing to the surface.
Various arrangements of production control valves are arranged at the wellhead in an assembly generally known as a tree, which is generally either a vertical tree or a horizontal tree. A horizontal tree arranges the production control valves offset from the production tubing and one type of horizontal tree is a Spool Tree™ shown and described in U.S. Pat. No. 5,544,707, hereby incorporated herein by reference for all purposes. A horizontal tree locks and seals onto the wellhead housing but instead of being located in the wellhead, the tubing hanger locks and seals in the tree bore itself. After the tree is installed, the tubing string and tubing hanger are run into the tree using a tubing hanger running tool (THRT) and a locking mechanism locks the tubing hanger in place in the tree. The production port extends through the tubing hanger and seals prevent fluid leakage as production fluid flows into the corresponding production port in the tree.
The tubing hanger typically has a plurality of auxiliary passages that surround the vertical bore associated with the production tubing. The auxiliary passages provide penetration access through the tubing hanger from outside the tree for hydraulic, optical, and electrical components located downhole. Electrical, optical, and hydraulic lines extend downhole alongside the tubing to control and/or power downhole valves such as a surface-controlled subsurface safety valve (SCSSV), temperature sensors, electric submersible pumps (ESP), downhole processors, and the like, as well as possibly provide for chemical reagent injection. Other types of lines than those listed may also be extended downhole. As the tubing hanger is landed and set in the tree, the auxiliary passages in the tubing hanger typically wet mate with auxiliary connectors located in the tree itself that may lead to a control unit mounted to the tree assembly.
A disadvantage of the conventional type of subsea wellhead assembly is that the tubing hanger must be large enough to house the number of passages extending through it. In addition to housing the passages, the tubing hanger requires a certain amount of structural integrity to support the production tubing. Thus there are only so many auxiliary passages that may be included in a given size tubing hanger before the tubing hanger needs to be enlarged. A large diameter tubing hanger also requires a large diameter drilling riser and BOP through which the tubing hanger must be run prior to installing the tree. Additionally, if the tubing hanger is made longer, the tree must also be lengthened, resulting in additional costs and weight for both items.
Another disadvantage of the auxiliary passages is that different wells may require different functions. Thus, trees must be “customized” to meet the needs of the particular well. Whereas certain downhole functionality may be common among many wells, other types of functionality may be more optional. Building a “one-size-fits-all” tubing hanger/tree thus would be inefficient because unwanted functionality built into the tree/tubing hanger adds unnecessary size, weight, and cost to the completion. Manufacturing costs alone would cause inefficiencies because of the added complexity and labor of manufacturing auxiliary ports into a solid tree body.
Another concern is that the downhole functionality needs of any given well may change over the life of the well. Specifically, a well may produce fluids at high pressure during the initial life of the well, but the pressure may taper off in the later part. With the initial higher production, the tree needs to be able to handle pressure as high as 15,000 psi. With such a high pressure, there is usually little need to install an ESP or engineer the capability of powering and controlling the ESP through the tubing hanger because the fluid pressure is adequate for fluid production. However, the pressure may taper off to as low as 5,000 psi during the life of the well and may require the use of an ESP. If so, the entire tree and completion may need to be pulled and replaced to add the ESP capability, thus costing the well operator valuable time and money. The initial tree could be designed for ESP functionality, but would result in a higher initial cost of the tree itself.